Apparatus, system, and method for in-situ extraction of hydrocarbons

ABSTRACT

An apparatus, system, and method are disclosed for in-situ extraction of hydrocarbons from a hydrocarbon bearing formation. The system includes a well drilled through a hydrocarbon bearing formation, and a completion unit that places an injection tube near a fluid injection of a target zone and a production tube near a fluid production point of the target zone. The injection tube comprising a tube with an inner diameter between about 1 inch and about 2 inches. The system includes a heat source, and a thermal conduit fluid that delivers heat from the heat source to the target zone. A mixer mixes an oxygen mixture and an injection unit injects the oxygen mixture into the depleted target zone to combust a coke remainder within the target zone. The system further includes a recycling unit configured to circulate a cool gas through the heated target zone to absorb the thermal energy disposed in the heated target zone.

CROSS-REFERENCES TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application No. 60/912,354 entitled “Apparatus, system, and method for in-situ extraction of oil from oil shale” and filed on Apr. 17, 2007 for Kevin Shurtleff and Stewart Cowley which is incorporated herein by reference. In addition, this application claims the benefit of U.S. patent application Ser. No. 11/782,463 entitled “Apparatus, system, and method for in-situ extraction of hydrocarbons” and filed on Jul. 24, 2007 for Kevin Shurtleff, which claims the benefit of U.S. Provisional Patent Application No. 60/820,256 entitled “Apparatus, system, and method for in-situ extraction of oil from oil shale” and filed on Jul. 25, 2006 for Kevin Shurtleff, both of which are incorporated herein by reference. This application also claims the benefit of U.S. Provisional Patent Application No. 60/981,027 entitled “Apparatus, system, and method for single well gas stimulation for enhanced oil recovery from an oil well” and filed on Oct. 18, 2007 for Kevin Shurtleff which is also incorporated herein by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the recovery of oil from hydrocarbon reservoirs, and particularly relates to in-situ recovery of heavy hydrocarbons such as kerogen from oil shale and residual hydrocarbon from conventional oil wells after primary recovery.

2. Description of the Related Art

Many hydrocarbon bearing formations do not flow hydrocarbons freely to the wellbore for extraction because of the high viscosity and/or solid state of the hydrocarbons. For example, kerogen in an oil shale is a high molecular weight hydrocarbon requiring temperatures over 300 degrees C. before it will break down and separate from the formation rock. In conventional oil wells, the primary recovery of hydrocarbons varies considerably, but typically about 30% of the hydrocarbons will be removed after the well stops producing economically. The remaining hydrocarbons are higher viscosity and/or higher molecular weight components of the original hydrocarbons, that will not flow into the wellbore for recovery after the primary oil recovery. In some conventional oil wells, a significant fraction including all of the oil may be heavy oil that will not flow freely to the wellbore without temperature and/or chemical intervention. In tar sands, the naturally occurring hydrocarbons do not flow freely to a wellbore.

The oil in oil shale formations is extracted by the thermal decomposition (pyrolysis) of a waxy, long-chain, hydrocarbon, called kerogen. An example of the pyrolysis reaction is shown in Equation 1, where a heavy, paraffin, molecule is split in half to form two lighter, unsaturated, molecules (i.e. molecules lacking full hydrogen). Of course, the heavy kerogen molecule can split in a number of ways, at times forming the simplest hydrocarbon, methane gas (CH4).

C22H46(s)+heat→2C11H23 (1,v)  Eq. 1

Kerogen was produced by the anaerobic (oxygen-free) decomposition of algae deposited between layers of sediment at the bottom of an ancient lake. The oil shale is actually a kerogen-rich, lucastrine marlstone (lake limestone or lake calcium carbonate). The richest oil shale deposits in Eastern Utah are found in the Parachute Creek member of the Green River Formation, which is located around the White River. The deposits vary in depth from surface exposures to layers buried over 3000 ft deep, with oil shale layers varying in thickness from 10 ft to 800 ft thick, and with an average oil content ranging from 10 gallons per ton to over 60 gallons per ton. Most other oil extraction processes are projected to be profitable for oil shale with oil content greater than 25 gallons per ton.

All approaches for extracting oil from oil shale share a common requirement: the oil shale must be heated to over 300 C to break-down the kerogen. In-situ processes heat the shale without removing it from the ground. The in-situ conversion process (ICP) developed by Shell uses a “fire and ice” approach. In order to prevent water from entering the heated zone, which would prevent the temperature from rising above 100 C, a large number of wells, spaced approximately 8 ft apart, are drilled around the perimeter. A refrigerated liquid is circulated through these wells to freeze the water in the ground, creating an ice wall. A central well is drilled and the water in the zone to be treated is pumped-out. Electric heaters are then inserted into the central well to heat the shale to the required temperature. The oil is typically removed through a second well, drilled adjacent to the heating well. The Shell process illustrates several key pieces of in-situ processes. First, water in the oil shale layer must be removed. Second, a huge amount of thermal energy must be injected into the oil shale. Third, the oil must be efficiently extracted.

Thus, for oil shales, current technologies include freezing pockets of the formation, and heating the formation within each pocket to recover kerogen from the formation. Such processes are energy intensive and require the drilling of multiple wells to recover kerogen from a relatively small section of the formation. An alternate oil shale process includes circulating heated combustion gas in a formation, but these processes introduce carbon dioxide into the formation that must be separated from any produced fluids, and are designed to work in water-free environments.

Oil shales and tar sands may also be recovered through bulk strip mining. The bulk material is mined out of the ground, and various surface processes can be utilized to strip any hydrocarbons from the bulk. Other mining techniques are possible, and such techniques inherently leave more of the hydrocarbons unrecovered than strip mining. Any of the mining processes introduce a number of environmental issues, including disposal of solvents, recovery of the mined land, and disposal of the shale remainder after the bulk of the hydrocarbons are removed.

For secondary recovery of oil wells and for oil wells with inherently heavy oil, several processes are available in the current technology. Some wells may be flushed with viscous fluids such as polymer based gels that rinse remaining oil from an injection well to an extraction well. The flushing process is expensive because of the fluid costs, and can only recover fluids that are essentially low viscosity although perhaps a bit higher viscosity than the oil recovered in the primary recovery. The flushing process is also subject to channeling between wells which can prevent full recovery of oil; channeling can be mitigated with fluid loss additives but these introduce damage into the formation. Further, some formations are sensitive to the introduction of water (e.g. formations with a high clay content) and therefore the flushing process is either ineffective or requires expensive anti-swelling additives to the fluid.

Secondary oil recovery has also been attempted with low-grade burning in the formation. The flame front in the formation reduces the viscosity of the remaining oil and drives the oil to an extraction well. The flame recovery process is difficult to initiate and control, it inherently consumes some of the oil in the formation, and it introduces combustion byproducts into the final produced fluids.

The processes in the current technology produce final products that have high molecular weight hydrocarbons. Low to middle weight hydrocarbon products (e.g. five to twelve carbons per molecule) are inherently more commercially valuable than heavy hydrocarbons. Some processes use a portion of the recovered hydrocarbons in the extraction process, for example burning them to heat some aspect of the recovery system. Further, as the recovery process proceeds, the molecular composition of the produced gas changes, often with lighter molecules recovered earlier and heavier molecules recovered later. Whether the produced fluids are burned or utilized as a product for sale, the changing of the molecular composition of the produced fluids introduces complications that must be managed.

With the current technologies no method, system or apparatus has been proposed to capture the thermal energy of a heated formation. As stated above, kerogen in an oil shale is a high molecular weight hydrocarbon requiring temperatures over 300 degrees Celsius before it will break down and separate from the formation rock. Once the economically recoverable kerogen is removed from the oil shale formation, the formation is allowed to cool before it is sealed with cement to prevent groundwater intrusion and contamination. Thus, a large amount of thermal energy is wasted with the current technologies.

Additionally, inefficient injection methods and injection tubing used in the present technologies results in additional heat being lost to the surrounding formation. With the deposits varying in depth from surface exposures to layers buried over 3000 ft deep, heat transferring apparatuses of the current technologies are inefficient, allowing thermal energy loss to the layers of rock deposited on top of the formation.

Accordingly, it would be an improvement over the current art to provide an apparatus, system and method to recycle thermal energy contained within a formation for use in subsequent formations. Beneficially, such an apparatus, system and method should efficiently deliver thermal energy from the surface to formations buried over 3000 ft deep. Similarly, it would be an improvement over the current art to provide an apparatus, system and method to economically and environmentally protectively seal a depleted formation.

SUMMARY OF THE INVENTION

From the foregoing, the Applicant asserts that a need exists for a system, method, and apparatus for recycling thermal energy contained within a formation for use in subsequent formations. Beneficially, such an apparatus, system and method should efficiently deliver thermal energy from hydrocarbon bearing formations which vary in depth from surface formations to formations buried over 3000 ft deep. Further benefits of the apparatus, system and method include utilizing a process that economically and environmentally seals a depleted formation.

The present invention has been developed in response to the present state of the art, and in particular, in response to the problems and needs in the art that have not yet been fully solved by currently available oil shale and secondary recovery systems. Accordingly, the present invention has been developed to provide an apparatus, system, and method for extracting hydrocarbons in-situ that overcome many or all of the above-discussed shortcomings in the art.

A method is disclosed for extracting hydrocarbons in-situ. The method includes performing a first stage extraction on a target zone of a hydrocarbon bearing formation by positioning an injection tube and a production tube within a well. A thermal conduit fluid is heated and injected into the target zone such that the heated thermal conduit fluid entrains in-situ kerogen to generate a production fluid. The production fluid is then produced. The method further discloses performing a heat recycling stage on the target zone in which heat contained within the target zone is recovered by pumping a cool gas stream into the target zone. The cool gas stream absorbs heat from the hydrocarbon bearing formation and the heated cool gas stream is extracted from the target zone.

In one embodiment the method includes performing a formation heating stage on the target zone by injecting an oxygen mixture into the target zone. In certain embodiments a coke remainder in the target zone is combusted to add thermal energy to the oxygen mixture. In one embodiment, the heated oxygen mixture comprises a carbon dioxide product of the coke combustion which is extracted through the production tubing. The heated oxygen mixture is then passed through a heat exchanger to heat a second thermal conduit fluid to perform a first stage extraction on adjacent second well. The second well may be adjacent to the first well. In certain embodiments the oxygen mixture comprises a thermal conduit fluid mixed with oxygen.

In certain embodiments the formation heating stage is performed after the kerogen has been substantially removed from the target zone. The method may further comprise sealing the well to substantially exclude oxygen from the target zone during the first stage extraction to prevent increased acidity of the production fluid.

In one embodiment the thermal conduit fluid heats the target zone to a temperature between about 300 degrees Celsius and about 400 degrees Celsius during the first stage extraction.

In certain embodiments the method includes injecting the thermal conduit fluid by passing the thermal conduit fluid through an injection tube. The diameter of the injection tube is proportioned to increase velocity of the thermal conduit fluid and to reduce residence time of the thermal conduit fluid within the injection tube. In certain embodiments the diameter of the injection tube is between about 1 inch and about 2 inches. In one embodiment, the diameter of the injection tube is between 1 inch and 1.66 inches.

In one embodiment the method includes performing a well abandonment stage on the target zone. In the well abandonment stage a solution of sodium bentonite and water is injected under high pressure into the target zone. The sodium bentonite and water solution seals the depleted hydrocarbon bearing formation with sodium bentonite and water to prevent intrusion and contamination of groundwater in the target zone. In certain embodiments the viscosity of the bentonite and water solution is adjusted to ensure that the bentonite and water solution fully expands within the target zone.

A system for extracting hydrocarbons is disclosed which includes at least one well drilled through an hydrocarbon bearing formation. A completion unit is configured to position an injection tube near a fluid injection point and a production tube near a production point. A heat source is configured to heat a thermal conduit fluid to a temperature selected to pyrolyze the hydrocarbon. An injection unit heats the target zone by circulating the thermal conduit fluid through the target zone. The thermal conduit fluid sweeps a hydrogen rich product of the pyrolyzation reaction into the production tube leaving a hydrogen poor product of the pyrolyzation reaction in the target zone. A combustion unit is configured to inject an oxygen mixture into the target zone and combust the hydrogen poor product which in turn heats the oxygen mixture. A cooling unit is configured to pump a cool gas stream into the target zone to absorb residual heat from the hydrocarbon formation. A recycling unit is configured to recycle the heat absorbed by the cool gas stream to heat an adjacent well. The system further discloses an abandonment unit that injects a solution of sodium bentonite and water under high pressure into the target zone. The sodium bentonite and water solution seals the depleted hydrocarbon formation with the sodium bentonite and water solution to prevent intrusion and contamination of groundwater in the target zone.

An apparatus for extracting hydrocarbons is disclosed. The apparatus includes a completion unit that positions an injection tube near a fluid injection point in a target zone of a hydrocarbon bearing formation and a production tube near a production point in the target zone. The inner diameter of the injection tube is between about 1 inch and about 2 inches. A heat source is configured to heat a thermal conduit fluid to a temperature selected to pyrolyze a hydrocarbon. An injection unit heats the target zone by circulating the thermal conduit fluid through the target zone. The thermal conduit fluid sweeps a hydrogen rich product of the pyrolyzation reaction into the production tube leaving a hydrogen poor product of the pyrolyzation reaction in the target zone. A combustion unit is configured to inject an oxygen mixture into the target zone and combust the hydrogen poor product which in turn heats the oxygen mixture.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic block diagram depicting one embodiment of a first stage extraction system for extracting hydrocarbons in-situ in accordance with the present invention;

FIG. 2 is a schematic block diagram of a controller in accordance with the present invention;

FIG. 3 is a schematic diagram depicting an isolation unit comprising a first and second horizontal well segment in accordance with the present invention;

FIG. 4 is a schematic diagram depicting a downhole burner in accordance with the present invention;

FIG. 5 is a schematic diagram depicting one embodiment of a first and second target zone in accordance with the present invention;

FIG. 6 is an illustration of a gas composition equilibrium diagram, for a heavy hydrocarbons in accordance with the present invention;

FIG. 7 is a schematic block diagram depicting one embodiment of a first stage extraction system for extracting hydrocarbons in-situ in accordance with the present invention;

FIG. 8 is a schematic diagram depicting one embodiment of circulating a cool gas through a high temperature zone in an offset well in accordance with the present invention;

FIG. 9 is a schematic block diagram of a concentric coiled tube in accordance with the present invention;

FIG. 10 is a schematic flow chart illustrating one embodiment of a N<method for in-situ extraction of hydrocarbons in accordance with the present invention;

FIG. 11 is a schematic flow chart illustrating one embodiment of a method for in-situ extraction of hydrocarbons in accordance with the present invention;

FIG. 12 is a schematic flow chart illustrating one embodiment of a method for in-situ extraction of hydrocarbonsin accordance with the present invention;

FIG. 13 is a schematic flow chart illustrating one embodiment of a method for in-situ extraction of hydrocarbons in accordance with the present invention;

FIG. 14 is a schematic flow chart illustrating one embodiment of a method for in-situ extraction of hydrocarbonsin accordance with the present invention;

FIG. 15 is a schematic flow chart illustrating an alternate embodiment of a method for managing the life cycle of a hydrocarbon extraction well in accordance with the present invention; and

FIG. 16 is an illustration of a vertical well to inject a pressurized gas and produce oil from the bottom of a well in accordance with one embodiment of the current invention.

DETAILED DESCRIPTION OF THE INVENTION

It will be readily understood that the components of the present invention, as generally described and illustrated in the figures herein, may be arranged and designed in a wide variety of different configurations. Thus, the following more detailed description of the embodiments of the apparatus, system, and method of the present invention, as presented in FIGS. 1 through 15, is not intended to limit the scope of the invention, as claimed, but is merely representative of selected embodiments of the invention. Some aspects of the present invention may be more fully understood in light of U.S. Provisional Patent Application No. 60/912,354 to J. Kevin Shurtleff entitled “Apparatus, system, and method for in-situ extraction of oil from oil shale,” filed on Apr. 17, 2007, incorporated herein by reference. Additionally, some aspects of the present invention may be more fully understood in light of U.S. patent application Ser. No. 11/782,463 to J. Kevin Shurtleff entitled “Apparatus, system, and method for in-situ extraction of hydrocarbons” filed on Jul. 24, 2007 which claims the benefit of U.S. Provisional Patent Application No. 60/820,256, “Apparatus, system and method for in-situ extraction of oil from oil shale,” filed on Jul. 25, 2006, and incorporated herein by reference. Similarly, some aspects of the current invention may be more fully understood in light of U.S. Provisional Patent Application No. 60/981,027 entitled “Apparatus, system, and method for single well gas stimulation for enhanced oil recovery from an oil well” and filed on Oct. 18, 2007 for Kevin Shurtleff which is also incorporated herein by reference.

FIG. 1 is a schematic block diagram depicting one embodiment of a first stage extraction system 100 for extracting hydrocarbons in-situ in accordance with the present invention. The first stage extraction system 100 includes at least one well 102 drilled through a hydrocarbon-bearing formation 104. The hydrocarbon-bearing formation 104 may be an oil shale, a conventional oil formation that has been produced with a primary recovery operation, a conventional oil formation with high molecular weight oil, a tar sand formation, and the like. The well 102 may be an open hole or cased hole completion. Throughout this disclosure certain references are made to oil shale formations. The oil shale formation references are for illustrative purposes only and are in no way limiting of the type of hydrocarbon formation that the present invention may be practiced on. Accordingly, one skilled in the art will recognize that the embodiments of the apparatuses, systems and methods presented in the following description may be equally applicable to other hydrocarbon bearing formations including but not limited to a tar sand formation, a conventional oil formation, a conventional oil formation with high molecular weight oil, and the like and should not be limited to oil shale formations.

In certain embodiments the first stage extraction system 100 is a “dry” process in that, in one embodiment, steam is not used as the thermal conduit fluid. When oxygen is available from the organic compound (e.g. C₄₀H₈₀O₂) or from water (H₂O) during pyrolysis, acetic acid is formed. Therefore, oil produced by steam pyrolysis is more acidic and corrosive. Accordingly, in certain embodiments of the present invention, oxygen is substantially excluded from the first stage extraction system 100. Oxygen is excluded from the thermal conduit fluid and from the target zone as much as possible.

Alternatively, in certain embodiments the first stage extraction system 100 comprises a “wet” process in that, in one embodiment steam is combined with another gas for form a mixture that is used as the thermal conduit fluid. In certain embodiments a hydrous pylrolysis produces hydrocarbons which have a higher economic value. In one embodiment the thermal conduit fluid comprises a steam/natural gas mixture that is injected in the first stage extraction system 100. In certain embodiments having a N<steam/natural gas composition, the composition comprises 20 percent steam by weight.

The first stage extraction system 100 further includes a completion unit 106 that positions an injection tube 108 near a fluid injection point 110 substantially at the bottom of a target zone 112 of the hydrocarbon-bearing formation 104, and that positions a production tube 114 near a fluid production point 116 substantially at the top of the target zone 112. The fluid injection point 110 and the fluid production point 116 may be an open hole segment of the well 102, perforations through a well casing and cement layer, and/or other fluid communication between the well 102 and the target zone 112 as understood in the art. In one embodiment, an explosive fracture technique, as is known in the art, is used to create a semi-spherical high gas permeability area around the target zone 112. Standard hydraulic fracturing, or explosive fracturing may be used in the first stage extraction system 100. The completion unit 106 may be a drilling rig, a completion rig, a coiled tubing unit, and/or other similar unit understood in the art. In one embodiment, the fluid production point 116 is substantially vertically above the fluid injection point 110, and the well 102 is a vertical well. In one embodiment, such as the embodiment illustrated in FIG. 16, the fluid production point 116 is disposed vertically below the injection point 110. In certain embodiments, such as the embodiment illustrated in FIG. 3, the well 102 comprises a horizontal well or horizontal well segments. In certain embodiments the first stage extraction system 100 includes a single well to both inject and extract a thermal conduit fluid 122, such as natural gas.

A height considered substantially at the bottom and/or top of the target zone 112 is dependent upon the specific application of the first stage extraction system 100, the thickness of the target zone 112, the diameter of the well 102, and the like. In almost any application, any placement of the fluid injection point 110 within a few feet of the bottom of the target zone 112 and placement of the fluid production point 116 within a few feet of the top of the target zone 112 comprises substantially near the bottom and/or top of the target zone 112. In some cases, for example, if the target zone 112 is thick, a placement of the fluid injection point 110 and the fluid production point 116 within ten feet or more of the top and/or bottom of the target zone 112 may comprise substantially at the top and/or bottom of the target zone 112. In one embodiment, the target zone 112 comprises only a portion of the hydrocarbon-bearing formation 104, and the bottom of the target zone 112 and the top of the target zone 112 are defined by the location of the fluid injection point 110 and the fluid production point 116, respectively.

The first stage extraction system 100 further includes an isolation unit 118 that isolates the fluid injection point 110 from fluid communication with the fluid production point 116 such that fluid flowing from the fluid injection point 110 to the fluid production point 116 flows through the target zone 112. The isolation unit 118 may be a packer in a cased well 102, a pair of packers in an open-hole well 102, and/or a cement plug. Any isolation unit 118 that prevents fluid from communicating within the wellbore 102 and forces fluid to travel through the target zone 112 from the fluid injection point 110 to the fluid production point 116 is contemplated within the scope of the present invention.

In one embodiment the first stage extraction system 100 further includes a heat source 124, which may be a burner 123 that burns a combustion mixture 129 to produce a combustion reaction. In certain embodiments, as described below with reference to FIG. 7 the heat source 124 may comprise heated gas from a formation heating stage system 700. In an embodiment a mixer 127 creates the combustion mixture 129 by mixing a fuel fraction 126 and an air fraction 128. The first stage extraction system 100 further includes a heat exchanger 130 that transfers thermal energy from the combustion reaction to a thermal conduit fluid 122 such that the thermal conduit fluid 122 is injected at a temperature sufficient to entrain hydrocarbons from the target zone 112 and thereby create a production fluid 132. In one embodiment, the heat exchanger 130 transfers thermal energy from the combustion reaction to the thermal conduit fluid 122 without mixing combustion products 134 into the thermal conduit fluid 122. The combustion products 134 may be vented to the atmosphere, and may be scrubbed for impurities and the like before venting. In certain embodiments the heat exchanger 130 transfers thermal energy from the heated gas of a formation heating stage system 700. In one embodiment, transferring thermal energy from the combustion reaction to the thermal conduit fluid 122 such that the thermal conduit fluid 122 is injected at a temperature sufficient to entrain hydrocarbons from the target zone 112 includes: determining a required injection temperature to entrain hydrocarbons based on the hydrocarbon type (e.g. typical kerogen requires 300° F.) and determining a temperature at the heat exchanger 130 required to achieve the required injection temperature.

In one embodiment, the injection tube 108 comprises an insulating layer to prevent excess heat loss during injection of the thermal conduit fluid 122. The injection tube 108 may be concentric coiled tubing, vacuum insulated tubing, insulated tubing, and/or concentric tubing. Concentric tubing may be a “tube within a tube” and may have spacers to prevent an inner tube from contacting the outer tube and decreasing insulation efficiency. In an alternate embodiment, the heat exchanger 130 is disposed within the wellbore 102 and the heat exchanger 130 transfers heat to the thermal conduit fluid 122 and prevents combustion products from mixing with the thermal conduit fluid 122.

The first stage extraction system 100 further includes an injection unit 120 that injects the thermal conduit fluid 122 into the fluid injection point 110 at an injection pressure selected to displace fluids within the target zone 112. The injection pressure may be a value above a formation fluid pressure and below a formation fracture pressure. The injection unit 120 may continuously apply the injection pressure to form a continuous gas bubble from the fluid injection point 110 to the fluid production point 116 that prevents formation fluids from migrating back into the target zone 112 from the surrounding hydrocarbon-bearing formation 104.

The first stage extraction system 100 further includes a production unit (not shown) that returns the production fluid 132 to a surface location through the fluid production point 116. The production unit may comprise a valve on the production fluid 132 line, a pump that brings oil or production fluid 132 from the fluid production point 116, and/or other fluid-raising technologies understood in the art. Various production units to raise wellbore fluids to the surface are known in the art, and the production unit is not shown in FIG. 1 to avoid obscuring aspects of the present invention.

The first stage extraction system 100 further includes a controller 133 having a reactor conditions module that interprets a composition of the production fluid 132 and adjusts a target temperature based on the composition of the production fluid 132. A product heat exchanger 136 heats the production fluid 132 to a target temperature, and a catalytic reactor 138 treats the production fluid 132, thereby reducing the average molecular weight of the production fluid 132. The product heat exchanger 136 in one embodiment receives a heat stream 140 from the first stage extraction system 100. The heat stream 140 may be from any thermal energy source, including a steam inlet, a heated combustion gas inlet, heat from a solar concentrator and/or heated gas from a formation heating stage system 700 on an nearby well.

In one embodiment, the reactor conditions module interprets a composition of the production fluid 132 and adjusts a target temperature based on the composition of the production fluid 132. The product heat exchanger 136 cools the production fluid 132 to the target temperature, thereby condensing a heavy oil fraction of the production fluid 132. The system 100 may include more than one product heat exchanger 136 and the reactor conditions module may adjust more than one target temperature based on the composition of the production fluid 132. For example, the reactor conditions module may adjust a first target temperature to a low value to condense heavy oil from the production fluid 132, and adjust a second target temperature to a high value to reduce the average molecular weight of the remaining production fluid 132 in the catalytic reactor 138.

The reactor conditions module may further calculate a free hydrogen target value. In one embodiment, the system 100 further includes a natural gas supply 142 that adds natural gas to the production fluid 132 based on the free hydrogen target value and the composition of the production fluid. The natural gas supply 142 may be pressurized, and/or a natural gas pump 144 may add the natural gas to the production fluid 132. In one embodiment, the free hydrogen target value is a value such that enough free hydrogen is added to the production fluid 132 to saturate substantially all of the hydrocarbons in the production fluid 132—i.e. to replace all double and/or triple bonds with straight chain hydrocarbons. In one embodiment, the final hydrogen/carbon ratio is about 2.25:1 (e.g. as in C₈H₁₈), where the ratios of the production fluid 132 and natural gas supply 142 can be estimated readily based on the respective compositions. For example, if the production fluid 132 averages C₁₈H₂₇ and the natural gas supply 142 averages C₁₋₂H_(4.4), the free hydrogen target value should be set such that approximately 8 moles of natural gas are added for each mole of production fluid 132. In one embodiment, the free hydrogen target value is calculated and a hydrogen supply (not shown) adds hydrogen gas (H₂), rather than natural gas, to the production fluid 132. The adjusted calculations for an embodiment utilizing hydrogen gas are a mechanical step for one of skill in the art.

The first stage extraction system 100 may include a scrubber 154 that strips at least one impurity from the production fluid 132 before treating the production fluid 132 in the catalytic reactor 138. Among the contaminants which may be present in the production fluid 132 are sulfur compounds, nitrogen compounds, and heavy metals or metalloids such as arsenic. The scrubber 154 may be positioned upstream or downstream of the product heat exchanger 136, although scrubbing before heating may lower the heat burden of the product heat exchanger 136. Various scrubbing systems are known in the art.

The treated production fluid 132 may be stored in a product storage 146. In one embodiment, the product storage 146 may be tapped to provide the fuel fraction at 126. Alternatively, or in addition, the natural gas supply 142 may be tapped to provide the fuel fraction 126. In alternate embodiments, the burner 124 may receive the fuel fraction 126 from the product storage 146, from the natural gas supply 142, and/or from an alternate fuel source. In one embodiment, the heat exchanger 130 receives heat input from an alternate heat source 124 in addition to and/or in replacement of the burner 124. For example, a solar concentrator (not shown) may provide solar heating to the heat exchanger 130. In one embodiment, the thermal conduit fluid 122 may be supplied by the product storage 146 and/or the natural gas supply 142. In one embodiment, the thermal conduit fluid 122 may be circulated through a nearby formation to such that the nearby formation heats the thermal conduit fluid 122. The nearby formation may be a depleted formation within the same well 102 and/or in an offset well (not shown).

In one embodiment of the first stage extraction system 100, the hydrocarbon-bearing formation 104 is an oil formation. The thermal conduit fluid 122 entrains the hydrocarbons by vaporizing the oil into the production fluid 132. The system 100 further includes a condenser 150 that condenses the oil from the production fluid 132 back to liquid oil at the surface. The condenser 150 may have a cooling stream 148 such as cooling water. The oil fraction of the production fluid 132 may be stored in an oil storage 152, while the volatile fractions of the production fluid 132 may be stored in the product storage 146.

The first stage extraction system 100 may further comprise a catalytic hydrocracking reactor, or upgrader. In certain embodiments, the thermal conduit fluid 122 comprises natural gas. In certain embodiments, the production fluid 132 comprises a natural gas portion. In one embodiment the natural gas injected into and produced from the target zone may comprise excess hydrogen due to a significant methane and ethane fraction, and therefore the produced fluid 132 may be passed through a catalytic reaction vessel at the correct temperature to crack some of the long hydrocarbon chain products from the kerogen into more commercially valuable small hydrocarbon chain products.

FIG. 2 is a schematic block diagram of a controller 133 in accordance with the present invention. In one embodiment, the controller 133 includes an operating conditions module 202, a reactor conditions module 204, and an air-fuel module 206.

The operating conditions module 202 interprets the air composition 220 and the fuel composition 218. The operating conditions module 202 may interpret the fuel composition 218 based on a natural gas composition and flow 216 and the production fluid composition and flow 215. For example, a natural gas composition and flow 216 may be 30 units (e.g. hundred ft³ at STP, etc.) comprising 90% CH₄ and 10% C₂H₆, the production fluid composition and flow 215 may be 70 units comprising 60% CH₄, 25% C₂H₆, 10% C₃H₈, and 5% C₄H₁₀. In the example, the operating conditions module 202 may determine a fuel composition 218 to be 69% CH₄, 20.5% C₂H₆, 7% C₃H₈, and 3.5% C₄H₁₀.

The air-fuel module 206 modulates the air flow and the fuel flow based on a heat requirement 214 and the fuel composition 218. The air-fuel module 206 may modulate the air flow and the fuel flow by setting an air flow target 212 and a fuel flow target 210. In one embodiment, the air-fuel module 206 further modulates the air flow based on the heat requirement 214, and modulates the fuel flow such that the combustion mixture 129 approximates a stoichiometric mixture. For example, if the heat requirement is 100 kJ, the air-fuel module 206 may set the air flow target 212 such that if a stoichiometric amount of fuel is burned with the air flow target 212, the heat requirement 214 is met. In the example, the air-fuel module 206 sets the fuel flow target 210 at the stoichiometric amount of fuel with the air flow target 212. The air-fuel module 206 may modulate the fuel flow such that the combustion mixture 129 has at least as much air as a stoichiometric mixture, and/or such that the combustion mixture 129 approximates a mixture having between 1 and 1.05 times a stoichiometric amount of air. For example, if the air flow target 212 is set to 1050 moles of air for a unit of time, and the stoichiometry indicates that 50 moles of air are required per mole of fuel, the air-fuel module 206 may set the fuel flow target 210 to a value of 21 moles per unit of time, to a value of at least 21 moles per unit of time (i.e. >=21 moles per unit of time), or to a value between about 20 moles and 21 moles per unit of time.

Achieving a specific air-fuel ratio, for example a stoichiometric ratio, may be based upon an estimated and/or measured fuel composition 218. For example, where the fuel fraction composition 208 is well understood to remain within 80% to 100% methane, an air-fuel ratio between about 9.5 and 11.2 mol air/mol fuel approximates a stoichiometric ratio. The product fluid composition 215 may be based upon knowledge of the produced fluids in the geographical region, upon periodic tests performed upon the production fluid 132 and made accessible as data to the controller 133, and/or through the use of a composition sensor such as a gas chromatography sensor and/or fluid density sensor on the production fluid 132. Similarly, the composition of the natural gas supply 142 may be based upon information provided by a utility provider, periodic testing, and the like. In one embodiment, an oxygen sensor installed on the combustion products 134 stream determines whether the combustion is near stoichiometric. In one embodiment, the controller 133 commands actuators (not shown) to achieve the fuel flow target 210 and the air flow target 212.

One of skill in the art will recognize that the operations of the air-fuel module 206 and the operating conditions module 202 may be iterative, and implementing an iterative solution for the fuel flow target 210 and air flow target 212 is a mechanical step for one of skill in the art. For example, the operating conditions module 202 may calculate a fuel composition 218 based on the natural gas composition and flow 216 and the product fluid composition and flow 215, while the air-fuel module 206 calculates an air flow target 212 based on the heat requirement 214 and a fuel flow target 210 such that the combustion mixture 129 approximates a stoichiometric mixture. In the example, if the heat requirement 214 increases—for example with a disturbance in the temperature of the inlet thermal conduit fluid 122—the production fluid amount 215 and/or the natural gas supply amount 216 increases thereby changing the fuel composition 218. Various solutions to the problem are readily apparent to one of skill in the art, including utilizing a fuel composition 218 for an earlier execution step of the controller 133 as an approximation. Typically, the execution steps of the controller 133, which may be a computer executing programming code on a computer readable medium, are fast relative to physical changes in the system 100 such as the variability in the fuel composition 218, such that the iterative nature of determining the fuel flow target 210 is reasonably ignored.

In one embodiment, the reactor conditions module 204 interprets a composition of the production fluid 215 and adjusts a catalyst target temperature 222 based on the composition of the production fluid. Interpreting the production fluid composition 215 may include reading a sensor value, reading a value from a datalink or data location, reading an electronic value such as a voltage and interpreting a composition from the electronic value, and/or other production fluid composition 215 determination method understood in the art. The catalyst target temperature 222 may be adjusted based on an equilibrium chart developed according to expected and/or detected compositions of the production fluid 132 as detailed in U.S. patent application Ser. No. 11/782,463.

The reactor conditions module 204 may further calculate a free hydrogen target value 224 based on the composition of the production fluid 215. In one embodiment, a natural gas supply 142 adds natural gas to the production fluid 132 based on the free hydrogen target value 224 and the composition of the production fluid 215. In one embodiment, the free hydrogen target value 224 is a value such that enough free hydrogen is added to the production fluid 132 to saturate substantially all of the hydrocarbons in the production fluid 132—i.e. to replace all double and/or triple bonds with straight chain hydrocarbons. In one embodiment, the final hydrogen/carbon ratio should be about 2.25:1 (e.g. as in C₈H₁₈), where the ratios of the production fluid 132 and natural gas supply 142 can be estimated readily based on the respective compositions.

For example, if the production fluid 132 averages C₁₈H₂₇ and the natural gas supply 142 averages C₁₋₂H_(4.4), the free hydrogen target value should be set such that approximately 8 moles of natural gas are added for each mole of production fluid 132. In one embodiment, the free hydrogen target value is calculated and a hydrogen supply (not shown) adds hydrogen gas (H₂) to the production fluid 132. In one embodiment, the reactor conditions module 204 calculates the free hydrogen target value 224 based on the composition of the production fluid 215 by selecting hydrogen target values 224 known to provide desirable end products from a catalytic reactor 138 according to an estimated and/or measured production fluid composition 215. The adjusted calculations for an embodiment adding hydrogen gas rather than natural gas 142 are a mechanical step for one of skill in the art.

FIG. 3 is a schematic diagram depicting an isolation unit 118A, 118B comprising a first horizontal well segment 302 and a second horizontal well segment 304 in accordance with the present invention. In one embodiment, the fluid production point 116 is substantially vertically above the fluid injection point 110. The fluid production point 116 is disposed within a first horizontal well segment 302, and the fluid injection point 110 is disposed within a second horizontal well segment 304. In the embodiment depicted in FIG. 3, the horizontal well segments 302, 304 are drilled off of the same well 102. However, the horizontal well segments 302, 304 may be drilled from separate wells 102.

The embodiment of FIG. 3 shows the fluid injection point 110 and the fluid production point 116 set to produce a first target zone 112A. In one embodiment, first target zone 112A may be plugged in the first horizontal well segment 302 and the second horizontal well segment 304 such that injected fluid into each horizontal well segment does not enter the first target zone 112A. The injection tube 108 may be positioned near a second fluid injection point substantially at the bottom of a second target zone 112B, and the production tube 114 may be positioned near a second fluid at production point substantially at the top of the second target zone 112B. An isolation unit 118A, 118B may isolate the second fluid injection point from fluid communication with the second fluid production point within the wellbore 102, and hydrocarbons may then be produced from the second target zone 112B. In the described manner, multiple target zones 112 may be produced from the same wellbore 102 and/or from the same horizontal well segments 302, 304.

FIG. 4 is a schematic diagram depicting a downhole burner 124 in accordance with the present invention. The downhole burner 124 depicted in FIG. 4 may be a part of a system 100 similar to that depicted in FIG. 1, wherein some of the parts of the system 100 are positioned as illustrated in FIG. 4. Notably, the burner 124 and heat exchanger 130 are depicted in the well 102. In one embodiment, the heat source 124 comprises a combustion reaction in a burner 124 disposed within a wellbore 102. The heat exchanger 130 is disposed within the wellbore 102, and the heat exchanger 130 transfers heat from the combustion reaction to the thermal conduit fluid 122 and prevents combustion products 134 from mixing with the thermal conduit fluid 122. The system 100 thereby heats the thermal conduit fluid 122 with minimal heat losses before the thermal conduit fluid 122 enters the target zone 112.

FIG. 5 is a schematic diagram depicting one embodiment of a first target zone 112A and second target zone 112B in accordance with the present invention. In one embodiment, the well 102 comprises a single vertical well 102, wherein the target zone 112A comprises a first target zone 112A. In one embodiment, after producing the hydrocarbons from the first target zone 112A, the well 102 is plugged 502 above the first target zone 112A. The injection tube 108 is positioned near a second fluid injection point 110B substantially at the bottom of a second target zone 112B, and the production tube 114 is positioned near a second fluid production point 116B substantially at the top of the second target zone 112B. An isolation unit 118 isolates the second fluid injection point 110B from fluid communication with the second fluid production point 116B within the wellbore 102, and a production unit produces hydrocarbons from the second target zone 112B. The embodiment of FIG. 5 may be a portion of a system 100 such as the system 100 depicted in FIG. 1.

In one embodiment, the second target zone 112B is stimulated to create at least one stimulated region 504 that improves fluid communication between the fluid injection point 110B and the target zone 112B, but does not provide a stimulated flowpath through the target zone 112B that connects the fluid injection point 110B and the fluid production point 116B. A stimulated region 504 is a region of the formation stimulated to create fissures, cracks, and/or wormholes within the formation. A stimulated flowpath (not shown) is a path that connects the fluid injection point 110B to the fluid production point 116B. Stimulated flowpaths are to be avoided to maximize effective use of thermal conduit fluid 122.

The stimulated region 504 may be a region 504 stimulated with an explosive. Other stimulation techniques understood in the art may be utilized, including acidizing treatments, hydraulic fracturing, and the like. It is a mechanical step for one of skill in the art to determine the vertical extent of a stimulation procedure and thereby avoid creating a stimulated flowpath through the target zone 112B between the fluid injection point 110B and the fluid production point 116B. The stimulated region 504 allows the injected thermal conduit fluid 122 to better penetrate the target zone 112B, and to better transfer heat to the hydrocarbons. A stimulated flowpath connecting the fluid injection point 110B and the fluid production point 116B, however, may create a short circuit path that reduces total hydrocarbon recovery from the target zone 112B as the thermal conduit fluid 122 is not forced out into the target zone 112B.

In certain embodiments the first stage extraction 100 of kerogen (C₂₀₀H₃₀₀N₅SO₁₁) through pyrolysis leaves a carbon or coke remainder 704 (illustrated in FIG. 7). FIG. 6 is a chart illustrating the equilibrium calculations when 1 mole of C₄₀H₈₂ pyrolyzed at 88 atmospheres (1300 psi) in a first stage extraction system 100. Note that in the illustrated embodiment methane and carbon are the only products if the system is allowed to reach equilibrium. In certain embodiments the coking reaction is self-parasitic in that some parts of the hydrocarbon transfer hydrogen to other parts to form methane (hydrogen rich) regions and carbon (hydrogen poor) regions. In certain embodiments the first stage extraction system 100 interrupts the pyrolysis reaction before the reaction reaches equilibrium by sweeping away the more volatile, hydrogen rich, components leaving the heavier, hydrogen poor components to continue the coking reaction. The result is that a hydrogen poor coke remainder 704 is left behind.

In certain embodiments, such as where the hydrocarbon formation comprises an oil shale formation, some processes have attempted oil extraction from oil shale by injecting high temperature steam. The steam breaks down the kerogen and strips the oil from the formation. The water and oil are pumped to the surface. This process may require the water and oil to be separated once produced, and the water typically must be purified before re-use and/or discharge. Further, equilibrium analysis suggests that steam combined with light hydrocarbons can form acetic acid.

FIG. 7 is a schematic diagram depicting one embodiment of a formation heating stage system 700 which includes pumping an oxygen mixture 702 into the target zone 112 at a controlled rate to initiate and control combustion of the coke remainder 704. In one embodiment a combustion unit 706 is configured to inject the oxygen mixture 702 at a controlled rated. In an embodiment a mixer 701 creates the oxygen mixture 702 by mixing an oxygen fraction 708 and an air fraction 710. In certain embodiments the formation heating stage system 700 further comprises an air-oxygen module (not shown) configured to modulate the air flow and the oxygen flow based on a heat requirement and air composition.

In certain embodiments, an oxygen mixture 702 is used comprising oxygen and ambient air. However, it is contemplated within the scope of the present invention that the oxygen mixture 702 may comprise solely oxygen. Alternatively, the oxygen mixture 702 may comprise oxygen and another gas including but not limited to natural gas, noble gases, and the like.

In certain embodiments the injected oxygen mixture 702 may be heated by a heater 712 before injection into the target zone 112 to provide a sufficiently high temperature to initiate combustion. In certain embodiments the percentage of oxygen contained within the oxygen mixture 702 and the rate at which the oxygen mixture 702 is injected into the target zone 112 may be controlled by a controller to keep the coke remainder 704 combusting but to avoid higher temperatures that may begin to decompose the surrounding rock (e.g. nacholite may begin to decompose around a temperature of about 500 deg C.), which may cause stability problems with the hydrocarbon bearing formation 104. Similarly, controlling the percentage of oxygen and rate at which the oxygen mixture 702 is injected into the target zone 112 may prevent excessive carbon dioxide 714 release (e.g. as carbonates are released from the decomposing rock).

In certain embodiments, the oxygen mixture 702 flow rate may be adjusted by recycling combustion products (e.g. adding excess carbon dioxide 714 circulated from the target zone) and/or by adding oxygen-enriched air to the oxygen mixture 702. The heat recovered 716 from the combusted coke remainder 704 is directly transferred to a second target zone that is performing a first stage extraction 100, and/or the heat recovered 716 may be utilized in some other system or process such as heating thermal conduit fluid 122 in a heat exchanger 130 and then injecting the thermal conduit fluid 122 into a second target zone in adjacent nearby well.

When the oil production rate from the target zone 118 in a first stage system 100 decreases to a point where it is no longer economically feasible to continue extraction, or where the coke remainder 704 has been burned in a formation heating stage 700, the now hot formation can be used as a source of thermal energy to provide heat for an adjacent well.

FIG. 8 is a schematic diagram depicting one embodiment of a heat recycling stage 800 which comprises circulating a cool gas 801 through a high temperature zone 804 in an offset well 802 in accordance with the present invention. Cool gas as used herein means a gas having a temperature between about ambient temperature and 135 degrees Celsius. In one embodiment the temperature of the cool gas means a gas having a temperature between about 80 degrees Celsius and about 135 degrees Celsius. In certain embodiments the cooling gas 801 is natural gas since it is readily available from the extraction process. The cool gas 801 is pumped down into the depleted zone 806 through the injection tube 108. The cool gas 801 extracts heat or thermal energy from the high temperature zone 804 and carries it back to the surface through the production tube 114, where it can be used as the heat source 123 in a heat exchanger 130 (FIG. 1) to preheat the thermal conduit fluid 122 of another well. According to one embodiment, the at least one heat source 123 of the first stage extraction system 100 may comprise an offset well 802, and the heated cool gas 801 conducts heat from the offset well 802 to the target zone 112 by way of the cool gas 801 circulating through a high temperature zone 804 in the offset well 802.

The heat recycling stage 800 may further comprise a circulation unit 810 configured to circulate the cool gas 801 through the offset well 802. In certain embodiments the depleted zone 806 comprises an area within a hydrocarbon-bearing formation 104 which has already been substantially depleted of hydrocarbons. The high temperature zone 804 retains heat from the first stage extraction system 100, the formation heating stage system 700 or both.

As used herein, an offset well 802 indicates a well connected to a depleted zone 806 that is not the target zone 112 intended for production. The well connected to the target zone 112 may be called the producing well 102. The offset well may be an adjacent well 802 to the producing well 102, a well 802 completely across the field from the producing well 102, or a separate horizontal segment 302, 304 within the producing well 102, where the separate horizontal branch is in fluid communication with the depleted zone 806, but is fluidly isolated—except for the intended delivery of the heated thermal conduit fluid 122 from the injection unit 120—from the target zone 112.

After circulation through the offset well 802, the heated cool gas 801 may then be further heated in the first stage extraction system 100 or directly injected by the injection unit 120 into the producing well 102. In certain embodiments the heated cool gas 801 may be injected simultaneously with a heated thermal conduit fluid 122, through separate injection tubes. In certain embodiments the heat recycling stage 800 produces a now heated cool gas 801 with a temperature of between about 400 Celsius to 200 Celsius and provides approximately one-half of the heat energy required to heat an adjacent well 102 for a first stage extraction 100, cutting energy costs and emissions in half. In one embodiment, such as where a formation heating stage 700 is performed, the target zone is heated to a temperature below 500 degrees Celsius, thus in certain embodiments the heat recycling stage 800 produces a now heated cool gas 801 to a temperature up to about 500 degrees Celsius.

After the high temperature zone 804 has been cooled to a point where it is no longer economically efficient to continue recycling the heat contained in the target zone 112, water can be added to the high temperature zone 804 to further cool the high temperature zone 804 to below 200 Celsius.

When the recycling stage 800 is complete and/or has become non-economic, the system may include an abandonment stage for the well 102. In the abandonment stage a water-sodium bentonite solution is injected into the target zone 112. The water-sodium bentonite solution invades cracks in the depleted shale that provide groundwater permeability. The water-sodium bentonite solution swells, sealing the cracks in the depleted formation 104. In certain embodiments the injection tube 108 is removed from the well 102 and the well 102 is sealed across the target zone 112 with neat cement. In one embodiment the production tube 114 may also be removed before sealing the target zone 112 with neat cement. In one embodiment the well 102 is cut off below the surface and the surface area around the well site is re-graded and re-planted.

In certain embodiments, the bottom of the oil shale in the Green River formation can be as deep as 3000 ft, and standard 2.875 dia., steel tubing may not be useable, since this may result in significant heat losses from the gas before it reaches the active oil shale zone. In one embodiment, the diameter of the injection tubing 108 is smaller than conventional injection tubing resulting in less heat loss via increased gas velocity and reduced residence time of the gas in the injection tube 108 (residence time is the time the gas spends in the tube). In one embodiment reduced heat loss is achieved through the use of vacuum insulated tubing (VIT) as the injection tubing. VIT is double-walled production tubing comprising an inner tube welded to an outer tube. The warm oil (or hot gas) travels within the innermost tube. The thin region between the inner tube and the outer tube is evacuated to provide an excellent thermal barrier and thus reduce heat losses from the transported material. Grant Prideco, one manufacturer of VIT, provides a thermal conductivity or “k-factor” of 0.006-0.02 BTU per hr-ft-° F. in higher temperature steam flooding type applications. This compares to a k-factor of 113 for stainless steel, and 0.16 for stagnant air. In other words, the thermal losses could be up to 5600 times less for VIT versus standard production tubing.

In the embodiment illustrated in FIG. 9 concentric coiled tubing (CCT) 900 is used as the injection tube 108. CCT 900 is a lower cost alternative to vacuum insulated tubing (VIT) to inject the thermal conduit fluid 122 into the target zone 112. CCT 900 is double-walled production tubing in which the hot gas or oil travels within the innermost tube 902. The region 904 between the inner tube 902 and the outer tube 906 is filled with a flexible insulating material (which may be air or other gas) to provide a thermal barrier and thus reduce heat losses from the transported gas. In certain embodiments the CCT 900 is continuous, eliminating joints and reducing heat losses. The inner tube 902 and outer tube 906 in CCT 900 are not welded to each other. This means the inner tube 902 is free to expand as it heats. Specialized slip joints at the end of the CCT 900 prevent binding and eliminate the need for pre-stressing of the inner tube 902, resulting in significant cost savings.

In one embodiment, the diameter of the injection tubing 108 is reduced resulting in less heat loss via increased gas velocity and reduced residence time of the gas in the injection tube 108 (residence time is the time the gas spends in the tube). By reducing the diameter of the inner tube 902, the gas injected through the inner tube 902 is forced through at a higher velocity. In certain embodiments the inner tube 902 has a diameter between about 1 inch and about 2 inches. In one embodiment the inner tube 902 has a diameter between about 1 inch and about 1.66 inches. A lower residence time means the gas has less time to transfer heat to the injection tube 108, reducing heat losses. In certain embodiments a higher pressure injection unit 120 may be utilized to force the same amount of gas through the smaller diameter tubing. While the current embodiments discuss the injection tube 108, one skilled in the art will recognize the same tubing may be utilized for both the injection tube 108 and the production tube 114. This is particularly true in an embodiment where the production tube 114 must maintain the temperature of the production fluid 132.

By using a concentric coiled tube 900, the diameter of the innermost tube 902 may be reduced while maintaining the dimensions of the outer tube 906, thus increasing the gas velocity and reducing the residence time of the gas in the injection tube without changing the outer characteristics of the injection tube 108.

The schematic flow chart diagrams herein are generally set forth as logical flow chart diagrams. As such, the depicted order and labeled steps are indicative of one embodiment of the presented method. Other steps and methods may be conceived that are equivalent in function, logic, or effect to one or more steps, or portions thereof, of the at illustrated method. Additionally, the format and symbols employed are provided to explain the logical steps of the method and are understood not to limit the scope of the method. Although various arrow types and line types may be employed in the flow chart diagrams, they are understood not to limit the scope of the corresponding method. Indeed, some arrows or other connectors may be used to indicate only the logical flow of the method. For instance, an arrow may indicate a waiting or monitoring period of unspecified duration between enumerated steps of the depicted method. Additionally, the order in which a particular method occurs may or may not strictly adhere to the order of the corresponding steps shown.

FIG. 10 is a schematic flow chart illustrating one embodiment of a first stage extraction method 1000 for extracting hydrocarbons in-situ in accordance with the present invention. The method 1000 may include performing 1002 a primary oil recovery on a target zone 112, wherein the remainder of the method 1000 comprises a secondary oil recovery on the target zone 112. For example, performing 1002 the primary oil recovery may comprise drilling a well 102 through the target zone 112, casing the well 102, stimulating the target zone 112, and flowing oil from the target zone 112 until the target zone 112 no longer delivers a commercially viable amount of oil to the wellbore.

The method 1000 continues with a completion unit 106 positioning 1004 an injection tube 108 near a fluid injection point 110 substantially at the bottom of a target zone 110 of a hydrocarbon-bearing formation 104. The method 1000 continues with the completion unit 106 positioning 1006 a production tube 114 near a fluid production point 116 substantially at the top of the target zone 112. The method 1000 includes producing 1008 hydrocarbons from the target zone 112.

Producing 1008 hydrocarbons from the target zone 112 includes an isolation unit 118 isolating 1010 the fluid injection point 110 from fluid communication with the fluid production point 116 such that fluid flowing from the fluid injection point 110 to the fluid production point 116 flows through the target zone 112. A heat source 123 is provided 1012. Producing 1108 hydrocarbons from the target zone 112 further includes an injection unit 120 with a low injection tubing residence time injecting 1014 a thermal conduit fluid 122 into the fluid injection point 110 at a pressure selected to displace fluids within the target zone 112, wherein the thermal conduit fluid 122 conducts thermal energy from the at least one heat source 124 to the target zone 112 such that the thermal conduit fluid 122 entrains hydrocarbons by sweeping volatile hydrocarbons pyrolyzed from formation kerogen from the target zone 112 to generate a production fluid 132.

The method 1000 further includes a production unit receiving 1016 the production fluid 132. In one embodiment, the hydrocarbon comprises oil, the thermal conduit fluid 122 entrains the oil by vaporizing the oil in the target zone 112, and receiving the production fluid 132 further includes a condenser 150 condensing 1018 oil from the production fluid 132.

FIG. 11 is a schematic flow chart illustrating a formation heating stage method 1120 according to one embodiment of the current invention. In certain embodiments the formation heating stage method 1020 may be performed after the first stage extraction method 1000 of FIG. 10 has received 1016 the production fluid 132. The method 1120 begins by mixing 1122 an oxygen fraction 708 with an air fraction 710 to produce an oxygen mixture 702. The oxygen mixture 702 is then injected 1126 into the target zone 112. Upon injection 1126 into the target zone 112, the oxygen mixture 702 and coke remainder 704 combust 1128. In certain embodiments the oxygen mixture 702 is heated by a heater 712 to a temperature which will combust 1028 the coke remainder 704 when oxygen mixture 702 is introduced into the target zone 112. The heat produced by the combustion reaction is then withdraw 1130 through the production tube 114. In certain embodiments the heat is withdrawn 1030 as a carbon dioxide product of the combustion reaction.

FIG. 12 is a schematic flow chart illustrating an embodiment of a heat recycling stage 1232 according to one embodiment of the current invention. The recycling stage begins by injecting 1234 a cool gas 801 into a high temperature zone 804 disposed within a target zone 112. The cool gas 801 is circulated 1236 through the high temperature zone 804 to absorb 1238 the thermal energy contained within the high temperature zone 804. The now hot cool gas 801 is then withdrawn 1240 and may be used to heat an adjacent well.

FIG. 13 is a schematic flow chart illustrating an embodiment of a well abandonment stage 1342 according to one embodiment of the current invention. The well abandonment stage begins by cooling 1344 the target zone 112 to a temperature below about 200 degrees Celsius. In certain embodiments the target zone 112 may be cooled by injecting water into the well 102. The well abandonment stage 1342 continues by mixing 1346 a sodium bentonite and water solution. The viscosity of the sodium bentonite-water solution may be adjusted 1348 to ensure that the sodium bentonite-water solution is fully expanded within the target zone 112. The sodium bentonite-water solution is then injected 1350 into the target zone 112. The injection tube 108 is then removed 1352 and the well 102 is plugged 1354 with neat cement. In certain embodiments the production tube is also removed in step 1052.

FIG. 14 is a schematic flow chart illustrating one embodiment of a method 1400 for in-situ extraction of oil from an oil shale in accordance with the present invention. The method includes drilling 1402 a vertical well 102 into an hydrocarbon bearing formation 104 and stimulating 1404 a target zone 112. The method further includes placing 1406 a concentric coiled tubing 900 at an injection point 110 substantially at the bottom of the target zone 112, and placing a production tubing 114 at a production point 116 substantially at the top of the target zone 112. The method further includes injecting 1408 a thermal conduit fluid 122 with a low tubing residence time into the target zone 112. The method includes sweeping 1410 volatile hydrocarbons pyrolyzed from formation kerogen from the target zone 112. The method concludes with producing 1412 the thermal conduit fluid 122 with entrained oil vapor and volatile hydrocarbons.

FIG. 15 is a schematic flow chart illustrating an alternate embodiment of a method 1500 for managing the life cycle of an oil shale extraction well in accordance with the present invention. The method includes performing 1502 a first stage extraction 100 on a target zone 112. When the first stage extraction 100 is economically complete, the method includes preparing 1504 the target zone for a formation heating stage 700. The method further includes injecting 1506 an oxygen mixture 702 into the target zone at a controlled rate and controlled oxygen/air ratio to combust the coke remainder 704 in the target zone 112. The method includes heating 1508 a thermal conduit fluid 122 for a first stage extraction 100 of a second target zone. The method further includes determining 1510 when the formation heating stage 700 is complete, and continuing to inject 1506 an oxygen mixture 702 into the target zone when the formation heating stage 700 is not complete. In one embodiment, the method includes performing 1512 target zone 112 abandonment procedures when the formation heating stage 700 is complete.

FIG. 16 is an illustration of a vertical well completion to inject a pressurized gas and produce oil from the bottom of a well in accordance with one embodiment of the current invention. The completion may comprise a casing 1602 secured within a well borehole by cement 1604. The well borehole may penetrate through the overburden 1616 and a capping layer 1614 (which may or may not be present) into the target zone 112. A tubing string 1608 may be disposed within an annulus 1610 of the casing 1602 and may run the length of the casing 1602. A packer 1612 a may be disposed within the casing 1602 to seal the casing 1602 and force a pressurized gas through a plurality of perforations 1620. In the illustrated embodiment, the packer 1612 a may maintain the tubing string 1608 approximately within the center of the annulus 1610. However, one skilled in the art will recognize that the tubing string 1608 may be disposed through the packer 1612 a in other locations. In certain embodiments, an additional packer 1612 b may be provided to prevent pressurized gas from short circuiting a gas diffusion zone 1618 by following the path indicated by arrow 1616 and out the tubing string 1608 without diffusing into the target zone 112 to create the gas diffusion zone 1630.

In one embodiment pressurized gas is continuously injected through the annulus 1610 in the direction generally indicated by arrows 1622. The pressurized gas is injected into the top of the target zone 112 through a plurality of perforations 1620. The pressurized gas may flow generally in the direction indicated by arrows 1618 as it diffuses into the gas diffusion zone 1630. As the gas flows up and away from the plurality of perforations 1620, the gas drives any hydrocarbons down and toward the wellhead 1640, thus increasing oil production. Placement of the tubing string 1608 near the bottom of the formation results in hydrocarbons being forced into the well 1640 by the pressurized gas.

In certain embodiments the pressurized gas comprises a thermal conduit fluid 122 heated to entrain hydrocarbons for production. Furthermore, in certain embodiments, the annulus 1610 comprises an injection tube 108 that carries the thermal conduit fluid 122. In addition, in certain embodiments, the tubing string 1608 serves as a production tube 114. Of course other tubing configurations described in relation to other embodiments above may be used with the injection and production positioning as set forth in the exemplary embodiment of FIG. 16.

In certain embodiments, the casing 1602, cement 1604, tubing string 1608, perforations 1620 and packers 1612 a and 1612 b may already be present from an initial hydrocarbon extraction process. In other embodiments, part of the components may be present from the initial hydrocarbon extraction process. Where some or all of these components are present, the process may only require cleaning the well, installing any missing components and injecting the thermal conduit fluid 122. 

1. A method for extracting oil from a hydrocarbon bearing formation, the method comprising: performing a first stage extraction on a target zone of a hydrocarbon bearing formation by: positioning an injection tube within a well; positioning a production tube within a well; heating a thermal conduit fluid; injecting the thermal conduit fluid into the target zone such that the heated thermal conduit fluid entrains in-situ kerogen to generate a production fluid; and producing the production fluid; performing a heat recycling stage on the target zone by: recycling the heat contained within the target zone by pumping a cool gas stream into the target zone, the cool gas stream absorbing heat from the hydrocarbon bearing formation; and extracting the heated cool gas stream.
 2. The method of claim 1, further comprising performing a formation heating stage on the target zone by: injecting an oxygen mixture into the target zone; and combusting a coke remainder in the target zone to add thermal energy to the oxygen mixture.
 3. The method of claim 2, further comprising; extracting the heated oxygen mixture through the production tube, the heated oxygen mixture comprising a carbon dioxide product of the coke combustion; passing the heated oxygen mixture through a heat exchanger, the heat exchanger configure to heat a second thermal conduit fluid for a first stage extraction of an adjacent well.
 4. The method of claim 2, wherein oxygen mixture comprises a thermal conduit fluid mixed with oxygen, the method further comprising injecting the heated oxygen mixture into an adjacent well and performing a first stage extraction on the adjacent well.
 5. The method of claim 3, further comprising injecting the second thermal conduit fluid into a second target zone and performing a first stage extraction on the second target zone.
 6. The method of claim 1, wherein the production fluid comprises liquid hydrocarbons and hydrocarbon vapor and wherein the thermal conduit fluid comprises a mixture of natural gas and water in the form of steam.
 7. The method of claim 2, wherein the formation heating stage is performed after the kerogen has been substantially removed from the target zone, the method further comprising sealing the well such that substantially no oxygen enters the target zone during the first stage extraction to prevent increased acidity of the production fluid.
 8. The method of claim 1, further comprising heating the target zone with the thermal conduit fluid, the target zone heated to a temperature between about 300 degrees Celsius and about 400 degrees Celsius during the first stage extraction.
 9. The method of claim 1, wherein injecting the thermal conduit fluid comprises passing the thermal conduit fluid through an injection tube having a diameter proportioned to increase velocity and reduce the residence time of the thermal conduit fluid within the injection tube, wherein the diameter of the tube is between about 1 inch and about 2 inches, and wherein the injection tube and the production tube are both positioned within a vertically oriented well.
 10. The method of claim 1, wherein injecting the thermal conduit fluid comprises passing the thermal conduit fluid through an injection tube comprising an insulation region disposed between an inner tube and an outer tube, wherein the inner diameter of the inner tube is between about 1 inch and about 2 inches.
 11. The method of claim 1, wherein injecting the thermal conduit fluid comprises passing the thermal conduit fluid through an injection tube comprising an insulation region disposed between an inner tube and an outer tube, wherein the inner diameter of the inner tube is between about 1 inch and about 1.66 inches.
 12. The method of claim 1, further comprising controlling the percentage of oxygen during the formation heating stage to maintain a combustion temperature below about 500 degrees Celsius within the target zone.
 13. The method of claim 1, further comprising exchanging heat from the cool gas stream exiting the well with a thermal conduit fluid of an adjacent well.
 14. The method of claim 1, further comprising performing a well abandonment stage on the target zone by injecting a solution of sodium bentonite and water under high pressure into the target zone, sealing the depleted oil shale with the sodium bentonite and water to prevent intrusion and contamination of groundwater in the target zone.
 15. The method of claim 14, further comprising adjusting the viscosity of the sodium bentonite and water solution such that the sodium bentonite and water solution fully expands within the target zone.
 16. A system for extracting hydrocarbons in-situ, the system comprising: at least one well drilled through a hydrocarbon bearing formation, the hydrocarbon bearing formation comprising a hydrocarbon; a completion unit configured to position an injection tube near a fluid injection point disposed within a target zone and to position a production tube near a fluid production point disposed within the target zone; a heat source configured to heat a thermal conduit fluid to a temperature selected to pyrolyze the hydrocarbon; an injection unit that heats the target zone by circulating the thermal conduit fluid through the target zone, the thermal conduit fluid sweeping a hydrogen rich product of the pyrolyzation reaction into the production tube leaving a hydrogen poor product of the pyrolyzation reaction in the target zone; a combustion unit configured to inject a oxygen mixture into the target zone and combust the hydrogen poor product to heat the oxygen mixture; and a cooling unit configured to pump a cool gas stream into the target zone to absorb residual heat from the target zone; a recycling unit configured to recycle the heat absorbed by the cool gas stream to heat an adjacent well; and an abandonment unit that injects a solution of sodium bentonite and water under high pressure into the target zone, sealing the depleted hydrocarbon formation with the sodium bentonite and water solution to prevent intrusion and contamination of groundwater in the target zone.
 17. The system of claim 16, wherein the heat source comprises an oxygen mixture N heated by a combustion unit in an adjacent well.
 18. The system of claim 16, further comprising a heat exchanger configured to transfer heat from the heat source to the thermal conduit fluid without mixing the heat source with the thermal conduit fluid.
 19. The system of claim 16, further comprising an mixer configured to mix an oxygen fraction and an air fraction to create the oxygen mixture, wherein the oxygen fraction comprises an oxygen flow, wherein the air fraction comprises an air flow and air composition, the system further comprising an air-oxygen module configured to modulate the air flow and the oxygen flow based on a heat requirement and air composition.
 20. The system of claim 19, wherein the air-oxygen module is further configured to maintain a combustion temperature under about 500 degrees Celsius.
 21. The system of claim 16, wherein the heat source is configured to heat the thermal conduit fluid to a temperature between about 300 degrees Celsius and about 400 degrees Celsius and wherein the combustion unit is configured to combust the hydrogen poor product after substantially the entire hydrogen rich product of the pyrolyzation reaction is swept into the production tube.
 22. The system of claim 16, wherein the injection tube comprises an insulation region disposed between an inner tube and an outer tube, wherein an inner diameter of the inner tube is between about 1 inch and about 1.66 inches.
 23. An apparatus for extracting hydrocarbons in-situ, the apparatus comprising: a completion unit configured to position an injection tube near a fluid injection point substantially at the bottom of a target zone of an oil shale formation and to position a production tube near a fluid production point substantially at the top of the target zone, the injection tube comprising concentric coiled tube with an insulating region disposed between an inner tube and an outer tube, wherein an inner diameter of the inner tube is between about 1 inch and about 2 inches; a heat source configured to heat the thermal conduit fluid to a temperature selected to pyrolyze a hydrocarbon; an injection unit that heats the target zone by circulating the thermal conduit fluid through the target zone, the thermal conduit fluid sweeping a hydrogen rich product of the pyrolyzation reaction into the production tube leaving a hydrogen poor product of the pyrolyzation reaction in the target zone; and a combustion unit configured to inject a combustion mixture into the target zone to combust the hydrogen poor product to heat the air.
 24. The apparatus of claim 23, further comprising a cooling unit and a recycling unit, the cooling unit configured to pump a cool gas stream into the target zone to absorb heat from the hydrocarbon bearing formation, the recycling unit configured to recycle the heat absorbed by the cool gas stream to heat an adjacent well.
 25. A method for extracting hydrocarbons, the method comprising: performing a first stage extraction on a target zone of an hydrocarbon formation by: positioning an injection tube within a well, the injection tubing disposed substantially at a top of the target zone; positioning a production tube within a well, the production tube disposed substantially at a bottom of the target zone; heating a thermal conduit fluid; injecting the thermal conduit fluid into the target zone such that the heated thermal conduit fluid entrains in-situ hydrocarbons to generate a production fluid; and producing the production fluid 